The present invention relates to a method of treating a gaseous mixture comprising carbon dioxide (CO2), hydrogen (H2), hydrogen sulphide (H2S), optionally carbon monoxide (CO), and optionally one or more additional combustible components, to obtain an H2/CO product stream and a CO2 product stream. The invention has particular application in the treatment of a syngas mixture, such as obtained from reforming or gasifying a carbonaceous feedstock, to obtain: an H2/CO product stream, for example an H2 stream or syngas (H2 and CO) of suitable purity for use in chemicals production, a refinery, or power production; and a CO2 product stream that is of suitable purity for geological storage or use in enhanced oil recovery (EOR).
The production of syngas mixtures via reforming gaseous or liquid feedstock or via the gasification of solid or liquid feedstock is well known, and has been a topic of research and development for decades. Such processes result in a crude syngas stream which, in addition to H2 and CO, also contains CO2 and other impurities. The gasification of solid and liquid feedstock, for example, typically results in an initial syngas mixture that can include a variety of impurities, such as but not limited to: particulates (which are typically removed in the slag of the gasifier, and/or are removed from the crude syngas mixture in an initial quenching step using water); CO2; CO (which can be considered an impurity if the intention is to obtain a high purity H2 stream, as opposed to a high purity syngas); CH4; H2S; carbonyl sulphide (COS); carbon disulphide (CS2); ammonia (NH3); nitrogen (N2); and argon (Ar).
CO2 and CO arise as oxidation products of the feedstock during gasification. H2S, and to a lesser extent other sulphur containing species such as COS and CS2, are usually also present in the crude syngas obtained from gasification of solid or heavy liquid feedstock, and arise from the reduction of sulphur present in the feedstock during gasification. The crude syngas mixture is often also subjected to a water-gas shift reaction to convert by reaction with H2O some or all of CO in the syngas to CO2 and H2, especially where the objective is to produce a high purity H2 stream rather than high purity syngas stream. This can have the incidental effect of also increasing the concentration of H2S in the resulting shifted sygnas mixture, due to further conversion of other sulphur species in the crude syngas stream to H2S during the water-gas shift reaction.
An array of syngas clean up technologies can be found in the art. Due to concerns over greenhouse gas emissions there is a growing desire to remove CO2 from hydrogen or syngas prior to their use as fuel, and H2 or syngas for chemicals production must meet even more stringent purity specifications. In a CO2 capture process the removed CO2 would typically be compressed so as to be stored underground or used in EOR. H2S must, where present, also be separated from the H2 or syngas, as if the H2 or syngas is to be used as a fuel then the presence of H2S will result in SOx (SO2 and SO3) in the combustion effluent (on which there may also stringent emissions limits), and if the H2 or syngas is to be used in a chemicals plant or refinery then H2S could be a poison for processes within the plant or refinery. It may not be practical or permissible to store the H2S with the CO2, and therefore removal of H2S from CO2 may likewise be required.
CO2 and H2S are often removed using a liquid solvent process (e.g. Selexol™, Rectisol®, or other such acid gas removal process). Here, a liquid solvent (for example methanol in the case of the Rectisol® process) is used to absorb and remove CO2 and H2S from the crude syngas, producing a purified syngas stream, a bulk CO2 stream and an H2S laden stream. The CO2 stream can be vented or directly pressurized and piped to storage or used for enhanced oil recovery (EOR), and the H2S laden stream (typically 10-80 mol %, more typically >20 mol % and usually preferably >40 mol % H2S) is sent to a Claus process for the production of elemental sulfur. In the Claus process H2S is partially combusted to form an H2S and SO2 mixture which can then undergo the Claus reaction to form elemental sulfur and a tailgas stream containing CO2, unreacted H2S and SO2, and other minor components. However, the aforementioned liquid solvent processes are both costly and have significant power consumption. This is especially true when the incoming H2S stream is dilute, e.g. <40%, as equipment sizes become large in order to accommodate the increase in H2S stream inerts.
An alternative approach that has been developed utilizes an adsorption based process, pressure swing adsorption, to purify syngas streams containing CO2 and at least one additional combustible component, such as H2S. In this process a CO2 rich stream with combustibles is formed which is then combusted, to produce a crude CO2 stream with combustion products that can then be removed using existing technologies to produce a CO2 stream of adequate purity for geological storage or EOR.
In particular, US-A1-2007/0178035, the disclosure of which is incorporated herein by reference, describes a method of treating a gaseous mixture comprising H2, CO2 and at least one combustible gas selected from H2S, CO and CH4, such as a gaseous mixture arising from gasification of carbonaceous fuel, hydrocarbonaceous fuel or biomass fuel. H2 is separated from the gaseous mixture, preferably by a pressure swing adsorption (PSA) process, to produce a separated H2 gas and a crude CO2 gas comprising the combustible gas(es). The crude CO2 gas is then combusted (preferably in an oxyfuel combustion process) in the presence of O2 to produce heat and a CO2 product gas comprising combustion products of the combustible gas(es), these combustion products being CO2 in the case of CO; CO2 and H2O in the case of CH4; and SOx (SO2 and SO3) and H2O in the case of H2S. Some H2 may also be present in the crude CO2 gas, which provides H2O as a combustion product. An additional carbonaceous fuel, hydrocarbonaceous fuel, or biomass fuel may also be combusted in the combustion process, the combustion of pulverized coal being given as an example. Where combustion products include SO2 and SO3, the CO2 product gas can be washed with water, to cool the gas and remove SO3, and maintained at elevated pressure in the presence of O2, water and NOx (NO and NO2) to convert SO2 and NOx to sulfuric acid and nitric acid. The acids and water may then be separated from the CO2 product.
Likewise, EP-A2-0262894, the disclosure of which is also incorporated herein by reference, describes a process for co-production of enriched streams of separate CO2 and H2 products from, for example, the effluent from a steam methane reformer. A PSA unit is used for the separation producing a primary stream of enriched hydrogen which may be liquefied. The purge stream from the PSA unit, comprising CO2 and combustible gases including CO, CH4 and H2, is combusted in the presence of pure or enriched oxygen in an internal combustion engine, gas turbine or other such combustion device to generate power and provide a stream consisting essentially of CO2 and water. This stream can then be cooled to condense out the water vapor, providing essentially pure CO2 that can be liquified.
Such processes, in addition to providing high purity H2 and CO2 streams, have the benefit of concurrently producing heat and/or power that can be put to use. However, the present inventors have found that, in some cases, separation of a sour (i.e. H2S containing) syngas mixture by PSA or other means will result in a separated CO2 stream that may be too dilute in combustible components to constitute a stream that, on its own and under the operating conditions under which combustion is to take place, can be combusted to form a stable flame. This may, in turn, compromise proper operation of the process, as flame instability will result in failure to stably combust the combustible components of the CO2 stream, which may result in said components remaining as contaminants in what would otherwise be the desired high purity CO2 product.
A generally known means of stabilizing combustion of a waste stream that would, otherwise, not be stably combusted is to combust also a support fuel of the type available for purchase on a futures basis (NYMEX, etc.), such as natural gas or light oils. However, the use of such traditional support fuels will increase the operational cost of the process in which they are employed.
There therefore remains a need for cost effective and reliable methods of treating a gaseous mixture, that comprises carbon dioxide (CO2), hydrogen (H2), hydrogen sulphide (H2S), optionally carbon monoxide (CO), and optionally one or more additional combustible components.